Alternating Liquid Gas Fracturing for Enhanced Oil Recovery of Well

ABSTRACT

A fracturing operation stimulate a region of a well by alternating between pumping liquid intervals and injecting gas intervals to the region. A given liquid interval can include slick water with or without proppant. The gas interval can include produced gas, and a given interval can be injected at pressures above or below fracture initiation pressures. In a depleted region, the stimulation can energize an existing fracture and can carry the proppant into the energized fracture. In an under-developed region, the stimulation can create a new fracture and can carry proppant into the new fracture. The liquid delivers the proppant, and turbulence from the injected gas at the fracture can help further carry the proppant therein. A diverter then temporarily seals the energized or new fracture so the injected gas temporarily sealed therein can interface with residual formation fluid therein, providing for enhanced oil recovery.

BACKGROUND OF THE DISCLOSURE

Hydraulic fracturing is widely utilized to improve hydrocarbon productivity from permeability challenged reservoirs. During a typical hydraulic fracturing treatment, a fracturing fluid is injected into a wellbore and penetrated into a rock formation at a pressure above the fracture initiation pressure so as to create tensile open area. Following the first initiation phase, propping agent (or “proppant”) is added to the fracturing fluid and injected into the newly created open area to prevent it from closing during production and also to provide conductive flow paths for hydrocarbon extraction from the target area. In essence, the proppant keeps the fractures open allowing for hydrocarbon production, and the proppant preferably stays in the formation, embedded in the fractures (used to “prop” fractures open). In the end, the overall success of the fracturing treatment and induced fracture characteristics (such as length, height, extent, and conductivity) are dependent on the rheological properties of the fracturing fluid which also influences proppant transport, distribution and mechanical behavior within the developed hydraulic fracture and/or reactivated natural fractures.

Current development in fracturing focuses heavily on liquid design. For example, viscosity of the water can be altered using natural or synthetic polymers, and/or the fluid and proppant can be pumped at high rates. Both techniques have advantages and disadvantages. Viscous fluid is a good carrier for the proppant, but is a poor penetrator in an ultra-tight formation. Viscous fluid can produce a wider fracture, but over only a relatively short distance. Slick water systems utilizing high pumping rates can penetrate deeper into the reservoir to form long, narrow fracture tunnels, but slick water can be a poor proppant carrier. In fact, the proppant may tend to settle down because a high enough pumping rate cannot be maintained to the degree of turbulence needed to transport proppant all the way to the extreme end of the fracture tunnel. Effectively sending proppant to any existing and/or newly created fractures still remains a challenge and this can impact the overall efficiency of the re-fracturing.

Treating a formation with two fluids is generally known in the art. For example, liquefied gas, such as water mixed with carbon dioxide, can be used as a fracturing fluid, such as disclosed in U.S. Pat. No. 3,664,422. Ultra-low viscosity fluids can be used to stimulate ultra-tight hydrocarbon-bearing formations, such as disclosed in US 2015/0345268, by separately injecting an ultra-low viscosity fluid (CO₂) used to create a fracture network and a conventional fluid used to carry proppant. Other than conventional fracture fluids, it is known in the art to use other techniques to fracture a formation. For example, liquefied petroleum gas can be used for fracturing a reservoir, such as disclosed in WO 2011/000089.

Even though different techniques can be used for fracturing a reservoir, unconventional reservoirs typically experience an initial high production rate, but that rate can quickly decline within a few months after reaching the peak rate. This usually results in low recovery efficiency even if hydraulic fracturing has been performed because the unconventional reservoir may have an extremely low matrix permeability. This type of production decline has been commonly observed in different unconventional reservoirs around the world, including the Barnett Shale, the Vaca Muerta shale, and so on.

Operators continue to search for practical solutions to enhance production and improve ultimate recovery from unconventional reservoirs. According to current industry practice, the most common ways to enhance production from an unconventional reservoir after facing the rapid production drop include drilling and stimulating infill wells, and re-fracturing existing wells in the field. The industry is also in the beginning stages of evaluating and applying enhanced oil recovery (EOR) methods, such as huff and puff gas injection, in unconventional reservoirs.

As is typical, hydraulic fracturing is used in the wellbores of an unconventional reservoir to initially stimulate the formation. In the fracturing, elongated fractures can be created and can be extended up to a thousand feet away from the wellbore. To keep the fractures conductive during production, the fracturing operation attempts to distribute proppant within the fracture. However, with such elongated fractures created so far from the wellbore, the proppant cannot be evenly distributed within the fracture surface to keep them conductive during production. As a result, zones within a developed fracture network that are loaded with little or no proppant tend to close readily and early in production life. The dynamic closure of the fracture network resulting from reservoir depletion and compaction could progressively reduce the reservoir contact area and hence contribute to the rapid production decline in the wells. In reality, only the fractures that are supported by large amounts of proppant and located within the vicinity of the wellbore (usually within hundreds of feet) can still stay open and conductive for long term depletion. Beyond these regions, the reservoir may remain under-developed due to early fracture closure, or the reservoir stays un-stimulated because a well-connected fracture network cannot be created.

As noted above, one solution to deal with rapid production decline of existing wells is to drill and then stimulate infill wells in between existing wells in an effort to increase the reservoir contact area between the depleted zones. Usually, infill wells are planned in the un-drained zones and are drilled within a certain distance from previously depleted regions near the existing wells. Once the infill wells are drilled, conventional hydraulic fracturing with plugging-and-perf or sliding sleeve, pillar fracturing, near-well diversion, or a combination of these technologies can then be utilized to stimulate the infill wells. As a result, fracturing the additional infill wells can help to stimulate previously un-touched zones and can increase the depletion efficiency and production within an acceptable time frame.

It is evident that fracturing additional infill wells can significantly increase the reservoir contact area and can help stimulate the un-touched zones, which could not be reached during the original treatment. However, the stress field can be altered and reoriented for the already depleted zones depending on a number of factors, such as the production duration, reservoir permeability, and geological conditions. The depletion induced stress changes can challenge the process of drilling the infill wells, especially in the situations where there are a great number of natural fractures and/or mega faults in the formation.

Furthermore, fracturing a new infill well in the vicinity of existing wells can potentially connect fractures from two adjacent wells, which is known as a “frac hit”. This creates an unexpected communication between the new infill well and the existing well, which can undermine the fluid and proppant placement for the infill well. Drilling infill wells can encounter wellbore stability related issues, frac-hit anomalies, and also unavoidable drilling cost, especially in the configurations with tightly spaced wells.

Instead of introducing new infill wells, re-fracturing the existing producing well is another viable way used in the industry to boost production. The existing well may have been initially stimulated several years ago using old technologies and knowledge. Therefore, re-fracturing the existing well with up-to-date technologies may present a promising option to boost production.

Compared to drilling a new infill well, re-stimulating existing wells can be much more efficient and cost effective for sustaining productivity and enhancing ultimate recovery. In the re-fracture treatment, operators may extend existing fractures by pumping additional fracturing fluid and proppant. Considering the existing proppant planned during the original treatment, however, the new proppant may not easily pass into the newly created fracture areas to keep them open. Moreover, embedment and agglomeration may take place to hold the “old” proppant in place so that the injected fluid during re-fracturing may not be able to push the consolidated and/or embedded proppant to the targeted areas.

Improving the near-well connection and proppant coverage for early closed fractures can face the same challenges in properly bypassing or mobilizing the already placed proppant so new proppant can be inserted while avoiding screening-out. Although extremely light and small proppant, a large volume of fracturing fluid, and a high injection rate could provide practical solutions to improve the proppant placement in these cases, these operations can result in unrealistic high completion costs and risks. Moreover, such operations are usually beyond instrument limitations.

Stimulating infill wells and/or re-stimulating existing wells can induce more open fractures in depleted zones. By using advanced particulate diverters, the fluid distribution can be temporarily manipulated to create a configuration with tightly spaced fractures. With proper engineering design, these newly created fractures can be constrained within a certain range to avoid frac-hit issues. Nevertheless, the success of stimulation is not only dictated by the number of created fractures and the developed extent of the fracture network. Instead, the effectiveness of fracturing process depends predominantly upon how far the proppant can be carried and distributed into the fractures. The further the proppant travels, the more producing length of the fracture or the longer the propped fracture length.

Optimizing recovery of hydrocarbon is the ultimate goal of each operator developing unconventional shale resources. The operators have primarily relied on the initial horizontal drilling and stimulation campaigns, followed by stimulated infill wells and then potentially re-fracturing of existing wells. The operators can expend substantial resources in evaluating reservoir conditions and deciding the best action(s). They may utilize all, some, or none of the options mentioned above to improve the recovery efficiency, which can be heavily reservoir dependent. In even the best of circumstances, recovery efficiency in unconventional reservoirs is quite low utilizing only drilling and conventional stimulation methods. Therefore, operators are now looking beyond drilling/completion methods and into Enhanced Oil Recovery (EOR) technologies to improve recovery efficiency in permeability challenged formations. EOR technology is in its infancy in unconventional reservoirs and brings potential improved recovery as well as its own unique set of challenges.

The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.

SUMMARY OF THE DISCLOSURE

According to the present disclosure, a method is disclosed of fracturing a well having at least one region including one or more existing fractures formed therein. The method comprises: stimulating the at least one region by alternating between pumping one or more first liquid intervals and injecting one or more first gas intervals to the at least one region; energizing at least one of the one or more existing fractures of the at least one region with the stimulation; carrying proppant into the at least one energized fracture with the stimulation fluid; temporarily sealing the at least one energized fracture with a diverter in the well; and interfacing the injected gas temporarily sealed in the at least one energized fracture with residual formation fluid therein.

Liquid for the one or more first liquid intervals can comprise at least one of a water-based fluid, an oil-based fluid, a polymer-based fluid, a foam, slick water, a synthetic fluid with low viscosity fluid and a high proppant carrying capacity, a linear gel, a cross-linked gel, and a liquefied gas. Gas for the one or more first gas intervals can comprise at least one of produced gas, produced lean gas, carbon dioxide, ethane-dominated gas, and rich hydrocarbon gas. Finally, the diverter can comprise at least one of a mechanical tool, a plug, a sliding sleeve, a particular diverter, a chemical diverter, a polyactic acid (PLA), and a ployglycolic acid (PGA).

Pumping the one or more first liquid intervals to the at least one region can involve delivering the proppant with at least one of the one or more first liquid intervals. For example, pumping the at least one first liquid interval delivering the proppant can comprise suspending the proppant in pumped liquid of the at least one first liquid interval; and delivering the pumped liquid comprising the suspended proppant into the existing fractures.

According to the disclosed method, “high” pressure gas—e.g., gas at or above a fracture initiation pressure—can be used. Therefore, injecting the one or more first gas intervals in the well can comprise injecting at least one of the one or more first gas intervals at a pressure at least at or above a fracture initiation pressure of the at least one region.

According to the disclosed method, “low” pressure gas—e.g., gas at or above (equal to or greater than) a reservoir pressure—can be used. Therefore, injecting the one or more first gas intervals in the well can comprise injecting at least one of the one or more first gas intervals at a pressure at or above reservoir pressure of the at least one region.

To stimulate the at least one region, one or more characteristics can be configured of at least one of the proppant, the one or more first liquid intervals, and the one or more second gas intervals for the at least one region. To energize the at least one existing fracture, an amount of pressure in the one or more first liquid intervals can be determined that is sufficient to reopen the at least one existing fracture.

Energizing the at least one fracture can take a number of forms according to the disclosed method. For example, energizing the at least one existing fracture can comprise: entering gas from the one or more first gas intervals into the at least one existing fracture in the at least one region; interfacing the entered gas with the residual formation fluid in a vicinity of the at least one existing fracture.

According to the disclosed method, energizing can extend existing fractures. For example, energizing at least one of the one or more existing fractures of the at least one region with the stimulation can further comprise extending at least one of the one or more existing fractures of the at least one region with the stimulation and carrying the proppant into the extension of the at least one extended fracture of the at least one region with the stimulation. To extend the at least one existing fracture, an amount of pressure and fluid volume can be determined that are sufficient to induce additional fracture length of the at least one existing fracture.

According to the disclosed method, turbulance can be used to carry proppant. For example, carrying the proppant into the at least one energized fracture with the stimulation can comprise: carrying the proppant into the at least one energized fracture with at least one of the one or more liquid intervals; and moving the proppant further with turbulence created by interaction of at least one of the one or more gas intervals with the one or more liquid intervals.

Temporarily sealing the at least one energized fracture with the diverter in the well can comprise at least one of: operating a mechanical tool as the diverter, installing a plug as the diverter, closing a sliding sleeve as the diverter, pumping a particular diverter as the diverter, and pumping a chemical diverter as the diverter adjacent the at least one energized fracture.

According to the disclosed method, vaporization, swelling, and miscibilty can be used for the enhanced oil recovery. For example, interfacing the injected gas temporarily sealed in the at least one energized fracture with the residual formation fluid therein can comprise using at least one of a vaporization, swelling, and miscibility mechanism.

The method can further comprise additional steps, such as producing fluid from the at least one region upon completion of the re-fracturing. The method can further comprise additional steps, such as: stimulating the at least one region by alternating between pumping one or more second liquid intervals and injecting one or more second gas intervals in the well to the at least one region; energizing at least one other of the one or more existing fractures of the at least one region with the stimulation; and carrying the proppant into the at least one other energized fracture with the stimulation.

According to the disclosed method, new fractures can be created. For instance, the method can further comprise: stimulating the at least one region by alternating between pumping one or more second liquid intervals and injecting one or more second gas intervals to the at least one region; and creating at least one new fracture in the at least one region with the stimulation; and carrying proppant into the at least one new fracture with the stimulation. Alternating between pumping the one or more second liquid intervals and injecting the one or more second gas intervals in the well to the at least one region can comprise: pumping a first of the one or more second liquid intervals to create the at least one new fracture; pumping, thereafter, a second of the one or more second liquid intervals with the proppant to carry the proppant into the at least one new fracture; and injecting, thereafter, a first of the one or more second gas intervals to the at least one new fracture to further carry the pumped proppant into the at least one new fracture and to interface the injected gas with the residual formation fluid in a vicinity of the at least one new fracture.

To alternate between pumping the liquid and injecting the gas in the well to the at least one region, a first of the one or more second liquid intervals can be pumped to create the at least one new fracture. Thereafter, a second of the one or more second liquid intervals can be pumped with the proppant to carry the proppant into the at least one new fracture. Thereafter, a first of the one or more second gas intervals can be injected to the at least one new fracture. Thereafter, a third of the one or more second liquid intervals can be pumped to compress the injected gas in the at least one fracture.

According to the present disclosure, a method is disclosed of using water-alternate-gas/gas-alternate-water to create new fractures. To fracture a well, the method comprises: stimulating at least one region of the well by alternating between pumping one or more first liquid intervals and injecting one or more first gas intervals to the at least one region of the well; creating at least one fracture in the at least one region with the stimulation; carrying proppant into the at least one fracture with the stimulation; temporarily sealing the at least one fracture with a diverter in the well; and interfacing the injected gas temporarily sealed in the at least one fracture with formation fluid therein.

For gas-alternate-water, alternating between pumping the one or more first liquid intervals and injecting the one or more first gas intervals in the well to the at least one region can comprise: injecting a first of the one or more first gas intervals at least above a fracture initiation pressure to create the at least one fracture; pumping, thereafter, a first of the one or more first liquid intervals with the proppant to carry the proppant into the at least one fracture; and injecting, thereafter, a second of the one or more first gas intervals to the at least one fracture to further carry the pumped proppant into the at least one fracture and to interface the injected gas with the residual formation fluid in a vicinity of the at least one fracture.

Injecting the first of the one or more first gas intervals at least above the fracture initiation pressure to create the at least one fracture can further involve filling the at least one fracture with the injected gas. Additionally, pumping the first of the one or more first liquid intervals further can involve extending the at least one fracture.

For water-alternate-gas (above fracture initiation or at or above reservoir pressure), alternating between pumping the one or more first liquid intervals and injecting the one or more first gas intervals in the well to the at least one region and creating the at least one fracture can comprise: pumping a first of the one or more first liquid intervals to create the at least one new fracture; pumping, thereafter, a second of the one or more first liquid intervals with the proppant to carry the proppant into the at least one new fracture; and injecting, thereafter, a first of the one or more first gas intervals to the at least one fracture to further carry the pumped proppant into the at least one fracture and to interface the injected gas with the residual formation fluid in a vicinity of the at least one fracture.

Thereafter, a third of the one or more first liquid intervals can be pumped to compress the injected gas in the at least one fracture. Alternating between pumping the one or more first liquid intervals and injecting the one or more first gas intervals in the well to the at least one region can instead involve pumping an initial one of the one or more first gas intervals in the well before first pumping the first liquid interval.

According to the present disclosure, a system for fracturing a well comprises pumping equipment, delivery equipment, and gas injection equipment. The pumping equipment is in fluid communication with the well and is configured to pump one or more of liquid intervals into the well at pressure. The delivery equipment is in fluid communication with the pumping equipment and is configured to deliver one or more of proppant and diverter to at least one of the one or more of the pumped liquid intervals. Finally, the gas injection equipment is in fluid communication with the well and is configured to inject one or more gas intervals into the well.

The system uses the pumping, delivery, and gas injection equipment to: alternate between pumping the one or more liquid intervals and injecting the one or more gas intervals to the region to stimulate at least one region of the well; energize at least one fracture of the at least one region with the stimulation; carry the proppant into the at least one energized fracture with the stimulation; temporarily seal the at least one energized fracture with the diverter; and interface the injected gas temporarily sealed in the at least one energized fracture with residual formation fluid therein.

To energize the at least one fracture of the at least one region with the stimulation, the system can be configured to at least one of: energize the at least one fracture from one or more existing fractures of the region with the stimulation; and create the at least one fracture in the at least one region with the stimulation. The gas injection equipment can comprise one or more compressors compressing gas for the one or more gas intervals.

According to the present disclosure, a method is disclosed of hydraulically fracturing and enhanced oil recovering a hydrocarbon-producing subterranean formation. The method comprises: ranking candidates of the subterranean formation; performing numerical analysis to quantify a proppant-carrying capacity of selected fracturing fluid and enhanced oil recovery efficiency of injected gas on the ranked candidates; selecting operational parameters of the selected fracturing fluid and the injected gas based on the numerical analysis; delivering the fracturing fluid, the injected gas, and a proppant to the ranked candidates of the subterranean formation at the selected operational parameters; temporarily sealing at least one energized fracture of the ranked candidates with diverter; and interfacing the injected gas temporarily sealed in the at least one energized fracture with residual formation fluid therein.

Selecting the operational parameters can comprise selecting one or more of a fracturing fluid type, a gas type, a proppant type, a proppant concentration, a pumping rate, and an alternating frequency between fluid and gas. Ranking the candidates can comprise ranking wells or well sections as the candidates based on a consideration of one or more factors selected from the group consisting of reservoir depth, pore pressure gradient, porosity, permeability, TOC, water saturation, Young's modulus, Poisson's ratio, rock strength, cohesion and shmin gradient.

Performing the numerical analysis can further comprise performing numerical analysis to quantify the proppant-carrying capacity under gas and liquid injection, liquid-gas compatibility, and enhanced oil recovery character; performing numerical analysis to quantify the proppant-carrying capacity under gas and liquid injection, liquid-gas compatibility, and enhanced oil recovery character with respect to fluid density, fluid viscosity, gas density, gas velocity, and formation fluid composition; and/or performing numerical analysis to quantify the proppant-carrying capacity under gas and liquid injection with various proppant types and concentrations.

Selecting the operational parameters can comprise: performing a simulation to predict a hydraulic fracture propagation, a fracture height growth, and a natural fracture reactivation; performing a simulation to model proppant transport within both main hydraulic fractures and a reactivated natural fracture network; performing a simulation to model a fluid diversion process; performing a simulation to assess a proppant embedment and crush and fracture surface closure behavior during production; performing a simulation to simulate the enhanced oil recovery; performing a simulation to forecast the enhanced oil recovery and production efficiency; and choosing a best stimulation design by a comparison of the predicted result corresponding to a typical design plan, wherein fracturing parameters of the planned stimulation operations are optimized based upon an extent of conductive reservoir volume, the enhanced oil recovery efficiency, and the production efficiency.

Selecting the operational parameters can comprise selecting a modified pumping schedule. To select the modified pumping schedule, an injection time, rate, proppant type, gas type, fluid property, liquid-gas or gas-liquid ratios, and alternating frequency between liquid and gas can be changed. The fluid property can include viscosity and density affecting fracture propagation and proppant transport process.

A change can be quantified of the fluid property, the gas type, and an impact thereof on the proppant-carrying capacity, the enhanced oil recovery efficiency, and fracture extent by performing numerical analysis.

Overall, selecting the operational parameters can involve performing the selection with respect to a defined geological condition using an integrated fluid-geomechanics workflow.

The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a treatment system according to one embodiment.

FIG. 2A schematically illustrates aspects of a treatment operation according to the present disclosure.

FIG. 2B schematically illustrates surface equipment for conducting the treatment operation according to the present disclosure.

FIG. 3 illustrates steps for the disclosed treatment operation.

FIG. 4A-4D illustrate steps for various examples of the disclosed treatment operation.

FIG. 5 illustrates a workflow for the disclosed treatment operation.

DETAILED DESCRIPTION OF THE DISCLOSURE

According to the present disclosure, a treatment operation stimulates (fractures/re-fractures) an existing well in an unconventional reservoir to improve production. To do this, the treatment operation uses a combination of hydraulic fracturing and gas injection to stimulate the well. Using both mechanical stimulation and enhanced oil recovery treatment in the well, the combination of hydraulic fracturing and gas injection can re-propagate existing fractures, re-open closed fractures, create new fractures, improve proppant coverage, and additionally offer enhanced oil recovery not achievable with conventional hydraulic fracturing techniques.

As an example, FIG. 1 illustrates a treatment system 10 according to one embodiment of the present disclosure for treating a formation intersected by a wellbore 12. To perform the treatment operation, the treatment system 10 as shown can be a zonal pressure isolation system, generally consisting of smaller tubing mounted with packers and fracture/sliding sleeves, inserted into existing casing of the wellbore 12 so various zones can be treated.

Other arrangements known and used in the art could be employed. In fact, fracturing of a given well may use more than one arrangement. In general, mechanical arrangements include, but not limited to, reworking the well with plug-and-perf techniques; having fracture sleeves already installed on the casing; using coiled tubing and packers to treat stages independently; using an arrangement of deployed bridge plugs to isolate zones; etc. As opposed to such mechanical arrangements, the treatment system 10 can fracture the well in a multi-stage hydraulic fracture by using perforation ball sealers, rock salt, or other particulate diverter to isolate perforations between fracture stages. As opposed to these particulate arrangements, the treatment system 10 can fracture the well in a multi-stage hydraulic fracture by performing the fracturing in successive stages in the wellbore and using chemical diverters to isolate previously stimulated regions so new regions can be stimulated along the entire wellbore. As expected, the treatment fluids in the particulate and chemical arrangement will follow the path of least resistance so the stages may be treated in an order defined by the flow that the fluid takes given the regions of the wellbore. Microseismic monitoring, downhole temperature sensing, and chemical tracers can be used to monitor the treatment.

As shown in FIG. 1, the system 10 has surface equipment 30 configured at the rig 32. This equipment 30 includes pumping equipment 34, proppant/diverter equipment 36, and gas injection equipment 38. A tubing string 20 or other conveyance is deployed from the rig 32 into the wellbore 12. The string 20 has fracture sleeves 24A-C or other types of valves disposed along its length at desired points. Various packers 22 may isolate portions of the wellbore 12 between the sleeves 24A-C into isolated zones. In general, the wellbore 12 can be an opened or cased hole, and the packers 22 may be any suitable type of packer intended to isolate portions of the wellbore into isolated zones.

As can be seen, the wellbore 12 includes existing fractures 14 in the various zones. The fracture sleeves 24A-C on the tubing string 20 between the packers 22 are initially closed during run in, but may be opened to divert treatment fluid to the isolated zones of the surrounding formation, as discussed below. The tubing string 20 may be part of a fracture assembly, for example, having a top liner packer (not shown), a wellbore isolation valve (not shown), and other packers and sleeves (not shown) in addition to those shown. If the wellbore 12 has casing, then the wellbore 12 may have casing perforations at the locations of the fractures 14.

In the treatment operation, operators deploy a setting ball to close the wellbore isolation valve (not shown). Then, operators pump fluid down the wellbore 12 to open a pressure-actuated sleeve (not shown) toward the end of the tubing string 20. As this point, stages of the treatment operation can begin. For example, operators selectively actuate the fracture sleeves 24A-C between the packers 22 to treat the isolated zones. A number of mechanisms and techniques may be used to open the fracture sleeves 24A-C. In a typical arrangement, successively dropped plugs or balls engage a respective seat in each of the fracture sleeves 24A-C and create a barrier to the zones below. Applied differential tubing pressure may then be used to shift the respective sleeve 24A-C open so that the treatment fluid may stimulate the adjacent zone.

For the surface equipment 30 used to treat the zones of the wellbore 12, the injection equipment 38 has a source of gas for injection into the tubing string 20. The gas source can be compressed gas in storage or can be actively compressed by compression equipment. The pumping equipment 34 has surface pump(s) to pump the treatment fluid (e.g., carrier fluid, fracture proppant, diverter, etc.) down the tubing string 20. The pumping equipment 34 may include one or more flow lines, pumps, control valves, a fluid reservoir (e.g., pit or tank), a solids separator, various sensors, stroke counters, and the like. The proppant/diverter equipment 36 may include a mixer, storage, controls, and the like and can add proppant and/or diverter as needed to the carrier fluid for being pumped as a proppant-laden slurry and/or a diverter-laden slurry down the tubing string 20 to the zone. In general, the rig 32 may have a fluid system, a launcher, a pressure control assembly (i.e., blowout preventer, a wellhead, a shutoff valve, etc.), and other necessary components. The launcher may be used to launch plugs, such as darts, fracture balls, or other actuating devices, for opening downhole fracture sleeves 24A-C disposed on the tubing string 20.

Various forms of treatments systems 10 can be used to treat the formation of the wellbore 12, and the above-embodiment is merely presented as an example. The treatment system 10 can allow for controlled selection of zones to be treated in the wellbore, or treatment can be generally applied to areas of the wellbore 12 or to the entire wellbore 12 with the treatment allowed to address given zones based on the characteristics of the formation, the fractures, the insertion of diverters, the use of plugs, etc.

With an understanding of the overall treatment system 10 used, discussion now turns to initial details of the treatment operation. In particular, FIG. 2A illustrates the treatment operation in schematic detail performed on a wellbore 12 with components of the disclosed treatment system 10. As shown, the treatment operation can be used for stimulating (fracturing/re-fracturing) a single, existing wellbore 12 at once. In this way, the treatment operation can energize and extend existing fractures 14 and effectively send proppant to the remote regions so that the need to drill infill wells in a tightly-spaced well configuration can be avoided. However, it will be appreciated that the disclosed operation can be used for a new well, including an infill well drilled adjacent an existing well. For already drilled infill wells, for example, use of the treatment operation and particulate diverters can control the fracture extent to minimize frac-hit issues. In fact, a reservoir may have a number of infill wells adjacent an existing well. In this instance, the wells can be treated with a zipper re-fracture operation in which the treatment operation is performed successively in zones of the adjacent wells to develop the fracture networks.

As before, the system 10 includes the surface equipment 30, including the pumping equipment (34), the proppant/diverter equipment (36), the gas injection equipment (38), and the like as noted above. Briefly, using the treatment operation discussed in more detail later, the surface equipment 30 injects treatment fluid 40 into targeted reservoir regions of the well 12 for re-opening existing fractures, to further extend existing fractures, and to create new fractures to gain more contact area.

As schematically shown, the treatment fluid 40 includes a liquid interval, slug, or cycle 42 alternated with a gas interval, slug, or cycle 44. In general, the liquid interval 42 can provide fracture pressures and can carry proppant 46. The viscosity of the liquid interval 42 helps move the proppant 46 and can avoid premature settling. The injected gas interval 44 can form turbulent flow and aid to push proppant 46 into the fractures and interact with residual oil in the surrounding area of fractures. Accordingly, the surface equipment 30 alternately pumps a liquid interval 42 and injects a gas interval 44 into the wellbore 12 to open depleted fractures 50, to create extensions 60 of existing fractures, and/or to create new fractures 80. The treatment can be designed according to the particular needs of the zones, the characteristics of the fractures, and other factors discussed below. The intervals 42, 44 can be repeated in multiple liquid-gas or gas-liquid sequences. In a given embodiment, the intervals 42, 44 can be alternated with a desired frequency, can start with gas or liquid first, and can have different pressures, flow rates, fluid amounts, etc. from one another. The liquid interval(s) 42 may or may not carry proppant 46 depending on the zone to be treated and the like, as discussed below.

Unlike existing technologies, the disclosed treatment operation can recover additional oil via multiple mechanisms, including both a propagation process 52 and an enhanced oil recovery process 54. In general, the operation can energize depleted fractures 50 in a propagation process 52 instead of just sealing them for good. These re-energized fractures 50 can be re-propagated and loaded with additional proppant 46, and increase their conductivity and permeability. Additional oil can be recovered through an enhanced oil recovery process 54. The operation 100 can also move existing proppant in the energized fractures 50 and can deliver new proppant 46. For example, the turbulent flow induced by gas injection can help transport the proppant 46 and can improve the proppant's coverage of fractured surfaces.

For example, the treatment fluid 40 pumped down the wellbore 12 can enter an existing fracture 50 of a depleted region 16 to be treated. In the propagation process 52 schematically shown, proppant 46 carried by the liquid 43 from the liquid interval 42 can enlarge the depleted fracture 50 of the zone, and the injected gas 45 from the gas interval 44 can mix with the liquid 43 and further carry the proppant 46 into the depleted fracture 50. In the enhanced oil recovery process 54 schematically shown, an interaction can occur between residual oil 18 in the depleted zone 50 and the injected gas 45 from the gas interval 44.

In addition to energizing a fracture 50, the propagation process 52 and the enhanced oil recovery process 54 can be used for further stimulation. For example, the treatment fluid 40 can extend the energized fracture 50 of the depleted region 16 with a new fracture extent 60 so that new fracture surface can be created with the liquid interval 42, the proppant 46, and the gas interval 44. As also generally shown, the treatment fluid 40 can create new fractures 80 in a target region, such as an under-developed region 17. In this scenario, there are two options to deliver proppant 46 into the fracture network: either combining liquid with gas or solely using specialized synthetic fluids. The option is selected based on the reservoir conditions, proppant availability, affordable cost, and production uplift.

According to the disclosed operation, the alternating pumping of the liquid and gas intervals 42, 44 is done to both carry the proppant 46 further into re-energized or newly created fracture area in the propagation process 52 and to also achieve enhanced oil recovery along the fracture surface in the enhanced oil recovery process 54. Unlike the conventional enhanced oil recovery operations, the gas interval 44 can be injected at “high pressure” usually at or above (equal to or higher than) the fracture initiation pressure to drive fracture propagation. To achieve the pressure, the surface equipment 30 can have a compressed source or compression equipment.

The gas 45 pumped in high rate can penetrate into an ultra-tight formation more easily than liquid 43. Given the low viscosity and high injection rate, the pressure drop associated with gas flow can be dominated by the flow velocity and attributed to turbulent flow. Therefore, the injected gas 45 contains more turbulent energy than the liquid 43, and its mixture with the liquid 43 can help to erode and mobilize the existing proppant packs and also aid to push the new proppant 46 further into the fracture 50, 60, and 80.

Additionally, as schematically shown in the EOR process 54 of FIG. 2A, the injected high pressure gas 45 can also help recover additional oil 18 left over through enhanced oil recovery by vaporization, potential swelling, and miscibility mechanisms. Any subsequent liquid interval 42 (e.g., slick water or specialized synthetic fluid) injected at high pressure and high rate that follows the gas interval 44 can help push the gas 45 into the matrix for more contact with the residual oil 18 and charge the gas 45 with more turbulent energy to carry the proppant 46, including both eroded existing packs and newly injected ones, further into the re-fractured zone to keep them open.

The proppant 46 can be selected based on reservoir conditions. For example, high concentrations and/or high-strength proppant can be used to minimize proppant embedment and crush to reduce the risk of the fractures closing. The rheological properties of the fracturing fluid are chosen to get the proppant to where it is most needed in the reservoir to maximize long-term production. Sufficient pumping equipment (34) is needed at surface to provide the required pressure, as well as all of the equipment for handling and mixing the proppant with the fracture fluid.

When a low-viscosity fluid (such as slick water) is selected, for example, the hydraulic fracture can be initiated, propagated, and well-contained within the given zone. High concentration and/or high-strength proppant 46 may tend to settle and accumulate on the bottom of the developed fractures or reactivated natural fractures, which may diminish the treatment efficiency. Thus, turbulence provided by the gas injection of the present operation can help carry the proppant 46 and provide more uniform distribution throughout the complex fracture network.

The type of liquid, its viscosity, the amount of liquid, the pumping pressure to apply, and other details related to the pumping of the liquid interval 42 of the treatment can be determined. In general, the liquid interval 42 can be a carrier fluid or a fracturing fluid used in the treatment, and a given interval 42 may or may not carry proppant 46. The liquid interval 42 can be a water-based fluid, an oil-based fluid, a polymer-based fluid, a foam, slick water, a specialized synthetic fluid, a linear gel, a cross-linked gel, or the like suited to the implementation. The liquid interval 42 can be a liquefied gas, such as a water-based fluid mixed with gas (e.g., carbon dioxide) (with or without proppant). Each of these fluids has different properties and applications, which can be selected based on the circumstances.

In one particular example, the liquid interval 42 includes slick water or other specialized synthetic fluid, such as a low viscosity fluid with high proppant carrying capacity and may be used with or without proppant. In fact, the operation can benefit from a synthetic fluid and techniques disclosed in U.S. application Ser. No. 15/666,327, filed 1 Aug. 2017, which is incorporated herein by reference.

The liquid interval 42, such as a polymer-based fluid of either slick water or other synthetic fluid, can contain surfactants that modify the phase behavior of the gas interval 44 at the gas-liquid interface of the introduced fluids. This mechanism can be useful both to transport the proppant 46 as well as to drive the fracturing fluid system to generate even greater complexity of the stimulated and propped reservoir volume. Any newly created proppant-filled fracture 80 can potentially be longer than those created traditionally by water-based fracturing fluid. In the end, flow back production of the region once production is resumed at a later time can recover additional oil from enhanced oil recovery of the depleted zone 50, from the virgin fracture zone 60, and from the new fractures 80 created in the previously under-stimulated regions 17.

The injected gas interval 44 offers enhanced oil recovery and helps push proppant 46 further. In general, the gas injection process can inject the gas interval 44 through a Huff & Puff method or cyclic gas injection. In the injection process, the gas may be injected at a high cycling pressure, which may be equal to an initial reservoir pressure but lower than a fracture initiation pressure required to create new fractures. Alternatively, the gas interval 44 can be injected at higher than the fracture initiation pressure as discussed herein. For example, the pressure for the gas injection can be configured relative to the reservoir pressure downhole or even relative to fracture pressures existing downhole, such as the fracture initiation pressure to induce a new fracture, the fracture propagation pressure to propagate an existing fracture, and fracture closure pressure to hold a fracture open. Either way, the gas 45 makes contact with the residual oil 18 in depleted regions and strips intermediate components of the oil 18 through a vaporization mechanism. The gas 45 can then be produced so those stripped components can be recovered in a surface separator.

Miscibility mechanisms may also help if the gas 45 at high cycling pressure either (i) is partially miscible or (ii) becomes asymptotic and miscible with the residual oil 18 through multiple contacts or through first contact with the residual oil 18. The miscible process will cause the residual oil 18 to swell and reduce its viscosity. The effectiveness of this cyclic gas enhanced oil recovery process 54 in the unconventional reservoir depends upon several factors, including injection gas composition, cycling pressure, gas oil contact time, reservoir temperature, depletion pressure, fracture intensity, fracture and matrix permeability, etc.

The gas type, injection pressure, and other factors can be configured to promote either one or multiple enhanced oil recovery mechanisms of gas extraction, swelling, and miscibility. The gas 45 at a lower pressure can tend to act as an extractor to recover residual oil 18 in the vicinity of fractures. Alternatively, the gas 45 at a higher pressure can dissolve in the residual oil 18 so the oil 18 can become more mobile for recovery.

The gas interval 44 can be produced gas, produced lean gas, carbon dioxide, ethane-dominated gas, rich hydrocarbon gas, and other type. The injected gas 45 can be mixed with another fluid to produce a viscous foam. Downhole, the injected gas 45 preferably has a gaseous state. At the point of injection, however, the gas 45 may or may not be in a gaseous state. For example, the gas 45 can be injected at a liquid state in the gas interval 44 and may subsequently change phase to the gaseous state downhole to achieve the purposes disclosed herein.

The liquid-to-gas ratios of the intervals 42, 44 and the alternation frequencies between them can be configured to achieve both the fracture propagation process and the enhanced oil recovery process according to the purposes disclosed herein. By way of comparison to conventional reservoirs, a typical water alternating gas process used simply to improve mobility of a flooding system for better sweep efficiency and improved oil recovery efficiency may alternate injection of water-to-gas ratios of about 0.5 to 4.0 volumes of water to about 1.0 reservoir volume of gas. The alternation frequencies can use about 0.1 to 2.0% pore volume (PV) slugs of each fluid. Because the present treatment operation is used to reopen existing fractures 50, extend fractures 60, create new fractures 80, achieve the enhanced oil recovery process 54, and the like, the treatment operation disclosed herein may have different liquid-to-gas ratios at different alteration frequencies and may additionally use liquids, gases, pressures, pump rates, injection rates, and the like considerably different than used for conventional water alternating gas injection (WAG) operations.

As noted above, by the end of treatment operation of a region, a diverter 70 can be applied to seal these re-stimulated fractures 50 to redirect the fracturing treatment to other regions. While treating other regions/stages, the pumped gas 46 sitting in the re-fractured regions can have sufficient time to penetrate into formation rock for an effective EOR recovery of residual oil 18.

Diversion can be achieved mechanically with tools, such as plugs, sliding sleeves, or other mechanical diverter 70 for the fracture treatment. The diverter 70 can be a particulate diverter or can be a chemical diverter, such as a polyactic acid (PLA), a ployglycolic acid (PGA), or the like. In fact, the treatment operation can benefit from a diverter, such as the Weatherford International's TBLOCKSURE® product line, and from techniques disclosed in U.S. application Ser. No. 15/439,757, filed 22 Feb. 2017, which is incorporated herein by reference. (TBLOCKSURE® is a registered trademark of Weatherford Technology Holdings, LLC.)

FIG. 2B schematically illustrates surface equipment 30 that can be used for conducting the treatment operation according to the present disclosure. As noted previously, the surface equipment 30 includes pumping equipment 34, proppant/diverter equipment 36, and gas injection equipment 38. A flow manifold 90 disposed at the rig allows for switching/cycling between the liquid pumping and gas injection from the equipment 34, 36, and 38. Depending on the needs downhole, the switching may be slow enough to allow for the pumping equipment 34 to be run on its own. After a sufficient pumping cycle, switching of the manifold's communication can be made, and then compressing the gas and injecting it can follow with the injection equipment 38. For faster forms of cycling, the pumping and compressing equipment 34, 38 may be run at the same time, and switching between them can be performed at the manifold 90 such that the used liquid/gas of a given cycle is inserted in the wellbore 12 and the unused gas/liquid is exhausted, vented, or recycled. This would allow for faster switching between the liquid and gas intervals 42, 44.

To pump a liquid interval 42 (i.e., treatment fluid, fracture fluid, slick water, etc.), the pumping equipment 34 typically uses one or more pumps (P), typically multiple pumps, to draw the liquid from a fluid tank (FT) and to pump the liquid interval 42 at a high flow rate through the wellhead (WH) and into tubing or other delivery mechanism 20 in the wellbore 12 of the well. (Should flowback be desired at any particular point, the wellhead (WH) can recirculate flowback from the annulus of the wellbore 12 to the fluid tank (TF) after handling by miscellaneous equipment.)

To introduce the proppant 46 to the liquid interval 42, the proppant/diverter equipment 36 can include an additive tank (AT) having the proppant 46, which can be injected by a metering device (D) into the pumped liquid interval 42 for suspension therein. An inline mixer (MX) can be used to mix the introduced proppant 46 and the liquid interval 42 for eventual entry into the delivery mechanism 20. A similar arrangement can be used for delivering diverter as discussed herein.

To inject a gas interval 44, the gas injection equipment 38 can have gas sources that feed gas through the wellhead (WH) and into the delivery mechanism 20 in the wellbore 12 of the well. Depending on the needs of an implementation, the gas sources can include a pressurized source of gas at a source pressure either above or below the fracture initiation pressure. Also depending on needs, the gas injection equipment 38 can include one or more compressors (CP), typically multiple compressors, to inject the gas interval 44.

To dictate the delivery of pumped liquid or injected gas through the wellhead (WH), a controller 95 can control various valves V₁-V₂ in the tubing of the manifold 90 to the wellhead (WH) to open/close communication from the equipment 34, 38. The controller 95 can also operate the compressors (CP), pumps (P), metering device (D), and other components of the surface equipment 30 for the configured treatment operation and its given stages.

As noted herein, the alternate pumping of liquid interval 42 and injection of gas interval 44 can be switched as needed for an implementation. In general, the switching between the pumping equipment 34 and the gas injection equipment 38 can be anywhere from seconds, minutes, hours, days, etc. In some of instances, while one of equipment 34, 38 is being used for a current stage of the treatment operation, it may be beneficial to maintain the other equipment 34, 38 operating. For example, it may be useful to maintain the pumps (P) operating, while the compressor (CP) is used to inject the gas interval 44. The manifold 90 may therefore include feedback loops 93, 94 and control valves V3-V4 that respectively allow for return of redirected liquid to the fluid tank (FT) and return of redirected gas to the gas source. Because the redirected gas and liquid may be at high pressure, flow rate, or the like, the feedback loops 93, 94 can include pressure regulating equipment, accumulators, vents, and the like.

A. Process of Treatment Operation

Given the above overview of the treatment system 10, the surface equipment 30, and the treatment operation, FIG. 3 presents particular steps for an embodiment of the treatment operation 100. As will be appreciated, the treatment operation 100 can be adapted to reservoir conditions the wellbore's previous fracture condition, depleted zones, under-developed zones, and other factors associated with an implementation. In fact, most wells will have multiple zones so the treatment operation 100 can be applied stage by stage and configured for the particular characteristics of each zone as needed. Accordingly, the treatment operation 100 can be conducted in a number of ways with these and other steps. In order to optimize the operation 100, necessary engineering steps, including numerical simulations and experimental tests, can be tailored to suit a particular reservoir.

The operation 100 as shown in FIG. 3 begins by selecting a region (i.e., zone, fracture network, existing fracture, depleted zone, under-developed zone, etc.) to be treated (Block 102). The selection may involve actuating a sliding sleeve at the region, moving fracturing equipment of straddle packers and valve to the region, installing a mechanical plug, or performing some other step that depends on the system used.

As is expected, the operation 100 to be performed on the selected region depends on the characteristics of the region, such as whether the region is a depleted zone, an under-developed zone, etc. Accordingly, a determination is made how to treat the target region (Block 110). Again, the treatment process 100 can be used to treat a depleted fracture zone, reopen existing fractures, extend existing fractures in the depleted zone, create new fractures in the depleted zone, create new fractures in an under-developed zone, etc.

In reality, only a small amount of regions in the well may actually contribute to and dominate the production. There are several explanations for this anomaly: (1) The fracture potential, which is a function of both geomechanical and reservoir attributes, varies across the reservoir; (2) The mechanical interaction between closely spaced fractures (stress shadow) causes an uneven fluid and proppant distribution; (3) The reactivation of pre-existing natural fractures and their interaction with propagating hydraulic fractures may complicate the fracture geometry and challenge the proppant placement; (4) Unconstrained fracture height growth may force the fluid and proppant to be sent into non-productive zones; and (5) Non-uniform fracture network closure can be induced by in-adequate proppant coverage, fine migration, proppant embedment, and degradation. Considering all these factors, hydraulic fractures often develop irregular and complex patterns, and micro-seismic data supports this understanding.

For these reasons, a number of different fracture scenarios may present in the existing well after it has been initially fractured for production. In a first scenario (I), hydraulic fractures in the well may have been well-developed and may have stayed open for hydrocarbon extraction. In a second scenario (II), the hydraulic fractures in the well may have been initially created, but they may have then readily closed in either the near-well or far-field regions due to proppant settling and/or embedment. In a third scenario (III), the hydraulic fractures in the well may not have been initiated or fully extended into the far-field region in the original fracture operation. A given well may have several of such fracture scenarios in its various zones.

Due to the complex fracture patterns and the complicated mechanical behaviors of the fractures in the well, the reservoir cannot be uniformly drained along the existing production zones after the original treatment, and re-fracturing may be suitable in the treatment operation for those regions that are underperforming with significant hydrocarbon still remaining in the reservoir. Accordingly, the treatment operation of the present disclosure can be implemented as a re-fracture operation and can re-stimulate well-developed flow channels (as in scenario I) to increase the fracture extent and to increase the fracture conductivity by re-injecting fluid and proppant. Elongated fractures that experience early closure or are disconnected from wellbore (as in scenario II) can also be recharged with additional fluid and proppant to improve the near-well connection and proppant coverage. For under-stimulated regions (as in scenario III), large volumes of fluid and proppant can be utilized to initiate and propagate healthy fractures at higher pumping pressure.

With the treatment determined for the selected region, the operation 100 as outlined in FIG. 3 configures the characteristics of the proppant(s) to be used in treating the target region (Block 112), the liquid interval 42 to be pumped to the target region (Block 114), and the gas to be injected to the target region (Block 116).

The configuration of the proppant, liquid, and gas depends on the target region and the treatment to be applied. As noted above, the liquid interval 42 is pumped into the wellbore 12 to reopen existing fractures 50, re-propagate existing fractures with extensions 60, create new conductive fractures 80, and the like in order to increase the productive surface-area of the reservoir. A series of chemical additives can be selected for the liquid interval 42 to impart a predictable set of properties, including viscosity, friction, formation-compatibility, and fluid-loss control.

To create, extend, and reopen fractures, the liquid interval 42 can be pumped into the wellbore 12 at a high rate to increase the pressure in the wellbore to a value greater than the breakdown pressure of the formation. The breakdown pressure is generally believed to be the sum of the in-situ stress and the tensile strength of the rock. Once the formation is broken down and the fracture is reopened, extended, or created, the fracture surface can be extended at a pressure called the fracture-propagation pressure, which is a sum of the in-situ stress, net pressure drop, and near-wellbore pressure drop.

The net pressure drop is equal to the pressure drop down the fracture as the result of viscous fluid flow in the fracture, plus any pressure loss caused by tip effects. The near-wellbore pressure drop can be a combination of the pressure drop of the viscous fluid flowing through the perforations and/or the pressure drop resulting from tortuosity between the wellbore and the propagating fracture. Thus, the properties of the liquid interval 42 are selected for the creation and propagation of such fractures.

The selected liquid interval 42 is also used to transport the proppant 46 into the fracture 50, 60, and 80 and to generate enough pressure within the fracture 50, 60, and 80 to create a wide fracture. The viscosity of the liquid interval 42 can be configured to fit the execution and the expected fracture geometry. In “slick water” treatments, low-viscosity fluids are pumped at high rates to generate elongated, well-contained, or complex fractures with low-concentrations of the proppant 46. To minimize settling of the proppant 46, pumping rates are sufficiently high to transport the proppant 46 over long distances (often along horizontal wellbores) before and after entering the fracture. The density of the liquid interval 42 can also be configured to affect the surface injection pressure and the ability of the fluid to flow back after the treatment 100.

In addition to the selection of the proppant 46 and the liquid interval 42, characteristics, such as the type of gas, the amount of gas, the injection pressure to use, and other details related to the injection of the gas interval 44 of the treatment 100 can be determined. Produced gas or other constituent may be suited for use depending on the implementation. As will be appreciated, the characteristics of each of these elements 42, 44, 46 can depend on the existing and known information of the region 16, its existing fractures 14, its production history, and the like.

Once the elements 42, 44, 46 are configured, the operation 100 then begins by treating the region (Block 120). This involves alternately pumping the liquid interval 42 (with or without the proppant 46) at the configured pressure into the well to the targeted region (Block 124) and injecting the gas interval 44 at the configured pressure into the well to the targeted region (Block 126). The gas interval 44 can be injected using compression equipment 38 at surface at a pressure either above or below the fracture initiation pressure. These alternating pumping and injecting steps (Blocks 124, 126) can be repeated in cycles as configured according to the needs of the target region.

Depending on the treatment, the operation 100 can affect the fracture network of the region in a number of ways (Block 130). For example, the operation 100 can re-open existing fractures 50 (Block 132); can extend existing fractures 50 to produce virgin fractures 60 (Block 134); can create new fractures 80 in the region (Block 135); can carry proppant 46 further into a fracture area, such as into a newly created fracture 80 or into a newly extended fracture 60 (Block 136); and can compress injected gas in the fracture for enhanced oil recovery (Block 138).

At some point in the disclosed treatment, those energized fractures 50 are temporarily isolated or disconnected from the well flow so the treatment fluid 40 and proppant can be diverted into other designated regions to create more fractures. Eventually, all the placed temporary seals or isolations are removed to allow hydrocarbon to flow into the wellbore.

To provide the temporary seals or isolations, plugging-and-perf or other similar mechanical diversion technologies can be used to isolate treated zones and redistribute the fluid flow to un-treated or under-developed zones during the re-fracture treatment. Solid diverting agents can be used to effectively block existing fluid entries and to guide the fluid distribution in re-fracturing treatments for unconventional reservoirs. Additionally, next-generation chemical diverters can be used for in-stage diversion and can self-degrade, which can save cost and time typically needed to remove the temporary seals of conventional diverters.

Accordingly, diverters 70 can be used to temporarily seal the fracture 50 of the target region (Block 140) so the injected gas 45 can soak with the residual oil 18 for enhanced oil recovery (Block 142). With the diverters 70 sealing the treated fracture(s), a new fracture 80 can be created in the existing region, or another existing fracture 14 can be reopened (Decision 105). For example, a liquid interval 42 (e.g., slick water or specialized synthetic fluid) can be pumped to re-stimulate other existing fractures 14 in a depleted region or to create new fractures 80 adjacent to the ones blocked by the diverter 70 (Block 124). A gas interval 44 can then be alternately injected (Block 126) and followed by another interval 42 of liquid (slick water or specialized synthetic fluid) (Blocks 124) to move proppant 46 further into the new fracture 80.

Once the selected region has been treated, the operation 100 can determine whether additional regions of the well need treatment (Decision 106), and the operation 100 can proceed with treating another region or can end. Various steps outlined above can be repeated, bypassed, or modified as needed to meet the needs of a particular implementation.

As noted above, the treatment operation 100 in treating a region (Block 120) alternates or switches between pumped liquid and injected gas intervals 42, 44 (Blocks 124, 126). The initial stage can include a pumped liquid interval 42 followed by an injected gas interval 44. This can be repeated in cycles configured for the particular characteristics of the wellbore 12 and the region to the treated. Cycling or switching can be repeated multiple times as needed, and the cycle lengths, frequencies, and other parameters of the intervals 42, 44 can be configured as needed. In general, a cycle of pumping of liquid in a liquid interval 42 can last days, hours, minutes, or seconds for a given situation, and the cycle of injecting gas in a gas interval 44 can also last weeks, days, hours, minutes, or seconds for a given situation and can be different from the liquid cycle as needed.

As discussed herein, the treatment operation 100 can inject the gas interval 44 (e.g., produced gas) at a pressure sufficient to inject gas at or above the reservoir pressure using compressor(s) of the injection equipment (38). Alternatively, the treatment operation 100 can inject the gas interval 44 (e.g., produced gas) at a pressure that exceeds the fracture initiation pressure.

A number of variations are possible in the cycles of the treatment operation 100. In a first variation, a liquid interval 42 is pumped (Block 124) and then alternated with injection of a gas interval 44 above the fracture initiation pressure (Block 126), such as provided by a compressor. In a second variation, a liquid interval 42 is pumped (Block 124) and then alternated with injection of a gas interval 44 at reservoir pressure (Block 126). In a third variation, a gas interval 44 is first injected at a pressure above fracture initiation pressure (Block 126) and then alternated with a pumped liquid interval 42 (Block 124). In a fourth variation, a gas interval 44 is injected at reservoir pressure (Block 126) and then alternated with a pumped liquid interval 42 (Block 124).

The particular needs and characteristics of a target region downhole can dictate which of the variations is used for a given treatment stage. Consideration of a number of factors, such as existing fracture network, proppant and fluid availability, desired goal of stimulating the zone, composition of residual oil present, etc., are considered when configuring the suited variation.

For one example of the decision of how to treat the selected region (Block 110), the region may be a depleted region 16 having previously developed fractures 14. Accordingly, the existing fractures 14 in the depleted region 16 can be re-energized to have their contact area and proppant load increased and to have residual oil recovered. Accordingly, the determination is made to re-propagate the existing fracture(s) 14 in the depleted region 16 (Block 110) by creating reopened fractures 50 and fracture extensions 60.

In this example, the operation 100 can begin by pumping an interval of slick water or specialized synthetic fluid carrying new proppant into the existing fracture 50 and by following the liquid interval 42 with injection of an interval 44 of produced gas. The gas can penetrate into the depleted region 16 around the fracture 50 to extract additional oil based on enhanced oil recovery. At the same time, the fracture length can be extended, and the proppant 46 can be pushed further into the virgin fracture 60. Process steps can then be repeated several times as necessary.

For another example of the decision of how to treat the selected region (Block 110), the region may be an under-developed region 17 having fewer developed fractures 14 than desired. However, interest may be to fill the previously developed fractures 14 of the region 17 with produced gas for enhanced oil recovery, but hydraulic fracturing to extend the existing fractures 14 may not be desired initially.

In this instance with the proppant 46, the liquid interval 42, and the gas interval 44 configured, the operation 100 begins by injecting the gas interval 44 as configured to fill the previously developed fractures 14 with produced gas for enhanced oil recovery (Block 126). Pumping of the liquid interval 44 (with and without proppant 46) can follow (Block 124) to open the fractures 14, carry proppant 46, introduce proppant 46 into the reopened fractures 50, compress the gas in the fractures 50, and the like. In this procedure, hydraulic fracturing may not be conducted to extend the fractures. The injected gas may only be used at this point for enhanced oil recovery in the developed region 16.

The fractures 50 can then be sealed with diverter 70 (Block 140). The diverter 70 temporarily plugs the fractures 50 and lets the gas soak with the residual oil in the depleted region 16 (Block 142). Following this step, operational steps can seek to create new fractures 80 in the under-developed region 17 adjacent to the sealed fractures 50 (Decision 105).

To create the new fractures 80, the operation 100 then begins by alternately pumping a liquid interval 42 (with the proppant 46) at the configured pressure in the well to the targeted region 16 (Block 124) and injecting a gas interval 44 at the configured pressure in the well to the targeted region 16 (Block 126). These alternating steps can be repeated in cycles as configured according to the needs of the region to create new fractures 80 (Block 135).

In this example, slick water or other synthetic fluid carrying proppant can be pumped to create the new fractures 80 in the under-developed region 17 adjacent to the sealed fractures 50. In these newly created fractures 80, gas alternately injected and mixed with the fracturing fluid of the liquid interval 42 pushes proppant 46 further into the fracture 80. Potentially, these new fractures 80 will have a longer propped length and height and better proppant coverage than what could have been created in initial treatment of the region using traditional fracturing technology. Likewise, the eventual flow back production may recover additional oil through the enhanced oil recovery provided by the injected gas in the new fractures 80 created in the under-developed region 17.

Process steps can then be repeated as necessary. For example, steps of treating the under-developed region 17 with alternating liquid and gas can be repeated to create additional fractures 80. Eventually, the operation 100 produces a sufficient network of newly-created fractures 80 for longer production, and the operation 100 can address other regions of the wellbore 12 (Decision 106).

1. Liquid-Alternate-Gas Operation with Gas at or Above Fracture Initiation Pressure (FIP)

One particular embodiment of the disclosed treatment operation 100 for a target region can involve a liquid-alternate-gas process with the gas used at or above fracture initiation pressure, such as provided by a compressor CP of injection equipment 38. As shown in FIG. 4A, the operation 100 seeks to reopen existing fractures in the region and uses gas injected at FIP (Block 150 a). The region can be a depleted region 16 having existing fractures 14 to be reopened and energized as energized fractures 50.

The operation 100 begins by configuring the characteristics of the proppant 46 to be used for the region 16 (Block 152), configuring the characteristics of the liquid interval 42, such as slick water, to be used for the region 16 (Block 154), and configuring the characteristics of the gas interval 44, such as produced gas, to be injected at FIP in the selected region 16 (Block 156).

Once configured, the process 100 begins by pumping a slick water interval 42 carrying proppant 46 to the region 16 (Block 160) to reopen existing fracture(s) 14 (Block 162). A produced gas interval 44 is then injected at high pressure (Block 164) for enhanced oil recovery and to push proppant 46 further into the fracture(s) 50 (Block 166). (As noted, “high” pressure can be at or above (equal to or greater than) the fracture initiation pressure.) Fracture extension can also be pursued. A diverter 70 is then utilized to seal off the energized fracture(s) 50 (Block 170) and to allow the gas to soak for enhanced oil recovery (Block 172).

The region 16 can then be treated to create new fractures 80 (Yes at Decision 107). To do this, a slick water interval 42 is pumped to create a new fracture 80 (Blocks 160 a, 162′), and a slick water interval 42 with proppant 46 is subsequently pumped to carry the proppant 46 into the new fracture 80 (Block 160 b). A produced gas interval 44 is then injected at high pressure (Block 164′) to push the proppant 46 further into the fracture 80 (Block 166′).

A diverter 70 can then be utilized to seal off the created fracture(s) 80 (Block 170) and to allow the gas to soak for enhanced oil recovery (Block 172). The region 16 can then be treated to create even more new fractures 80 or not (Decision 107). Various steps outlined above can be repeated, bypassed, or modified as needed to meet the needs of the implementation.

2. Liquid-Alternate-Gas Operation with Gas at or Above Reservoir Pressure

Another particular embodiment of the disclosed treatment operation 100 for a region 16 can involve a liquid-alternate-gas process with the gas used at “low pressure”— e.g., at or above (equal to or greater than) reservoir pressure but less than the fracture initiation pressure. As shown in FIG. 4B, the operation 100 seeks to reopen existing fractures in the region and uses gas injected at or above reservoir pressure (Block 150 b). Again, the region can be a depleted region 16 having existing fractures 14 to be reopened and energized as energized fractures 50.

The operation 100 starts by configuring the characteristics of the proppant 46 to be used for the region 16 (Block 152), configuring the characteristics of the liquid interval 42, such as slick water, to be used for the region 16 (Block 154), and configuring the characteristics of the gas interval 44, such as produced gas, to be injected at reservoir pressure in the region 16 (Block 156).

Once configured, the operation 100 begins by pumping a slick water interval 42 carrying proppant 46 to the region 16 (Block 160) to reopen existing fractures 14 (Block 162). A produced gas interval 44 is then injected at reservoir pressure (Block 164) for enhanced oil recovery (Block 164). Then, a slick water interval 42 is pumped at high rate (Block 160 a) to push the gas slug, to carry the proppant 46 further into the reopened fracture(s) 50, and to increase the gas pressure for higher EOR efficiency (Block 162′). Fracture extension can also be pursued.

At this point, a diverter 70 is then utilized to seal off the energized fracture(s) 50 (Block 170) and to allow the gas to soak for enhanced oil recovery (Block 172). The region 16 can then be treated to create new fractures 80 (Yes at Decision 107). To do this, a slick water interval 42 is pumped (Block 160 a) to create a new fracture 80 (Block 162′), and a slick water interval 42 with proppant 46 is pumped to carry the proppant 46 into the new fracture 80 (Block 160 b). A produced gas interval 44 is injected at reservoir pressure for enhanced oil recovery (Block 164′). Then, a slick water interval 42 is pumped at a high rate (Block 138′) to push the gas, to carry the proppant 46 further into the fracture 80, and to increase the gas pressure for higher EOR efficiency (Block 169′). Various steps outlined above can be repeated, bypassed, or modified as needed to meet the needs of the implementation.

3. Gas-Alternate-Liquid Operation with Gas at or Above Fracture Initiation Pressure

Yet another particular embodiment of the disclosed treatment operation 100 for a region can involve a gas-alternate-liquid process with the gas used at “high pressure”—e.g., at or above (equal to or greater than) fracture initiation pressure (FIP). As shown in FIG. 4C, the operation 100 seeks to create fractures in a region and uses high pressure gas (Block 150 c). The region can be an under-developed region 17 to be treated to create new fractures 80.

The operation 100 starts by configuring the characteristics of the proppant 46 to be used for the region 17 (Block 152), configuring the characteristics of the liquid interval 42, such as slick water, to be used for the region 17 (Block 154), and configuring the characteristics of the gas interval 44, such as produced gas, to be injected at FIP in the selected region 17 (Block 156).

Once configured, the operation 100 begins by injecting a produced gas interval 44 at FIP (Block 180) for enhanced oil recovery and to create fracture(s) 80 (Block 182). A slick water interval 42 is then pumped carrying proppant 46 (Block 184) to open the fracture(s) 80 and possibly extend them (Block 186). A produced gas interval 44 is then injected at FIP (Block 188) for enhanced oil recovery and to push the proppant 46 into the fracture area (Block 189).

At this point, a diverter 70 is then utilized to seal off the fracture(s) 80 (Block 170) and to allow the gas to soak for enhanced oil recovery (Block 172). The region 17 can then be treated to create additional new fractures 80 (Yes at Decision 107). Previous steps (Block 180 to 189) can then be repeated to create fracture(s) 80, prop with proppant 46, and fill for enhanced oil recovery. Various steps outlined above can be repeated, bypassed, or modified as needed to meet the needs of the implementation.

4. Gas-Alternate-Liquid Operation with Gas at or Above Reservoir Pressure

Yet another particular embodiment of the disclosed treatment operation 100 for a region 16 can involve a gas-alternate-liquid process with the gas used at or above reservoir pressure. As shown in FIG. 4D, the operation 100 seeks to create fractures in a region and uses gas at or above reservoir pressure (Block 150 d). Again, the region can be an under-developed region 17 to be treated to create new fractures 80.

The operation 100 starts by configuring the characteristics of the proppant 46 to be used for the region 17 (Block 152), configuring the characteristics of the liquid interval 42, such as slick water, to be used for the region 17 (Block 154), and configuring the characteristics of the gas interval 44, such as produced gas, to be injected at reservoir pressure in the selected region 17 (Block 156).

Once configured, the operation 100 begins by injecting a produced gas interval 44 at reservoir pressure for enhanced oil recovery (Block 190). (Chemical injection can be used to create the desired gas in situ downhole at the region 17 so that injection of the gas at surface may not be performed at the start.)

A slick water interval 42 is pumped at high rate (Block 191) to create new fracture(s) 80 and increase gas pressure for enhanced oil recovery (Block 192). A slick water interval 42 is pumped carrying proppant 46 to open the fracture(s) 80 and possibly extend them (Block 193). A produced gas interval 44 is then injected at reservoir pressure (Block 194). A slick water interval 42 is pumped at high rate (Block 195) to push the gas and carry the proppant 46 further into the fracture(s) 80 and increase the gas pressure for higher EOR efficiency (Block 196).

At this point, a diverter 70 is then utilized to seal off the fracture(s) 80 (Block 170) and to allow the gas to soak for enhanced oil recovery (Block 172). The region 17 can then be treated to create additional new fractures 80 (Yes at Decision 107). Previous steps (Block 190 to 196) can then be repeated to create fracture(s) 80, prop with proppant 46, and fill for enhanced oil recovery. Various steps outlined above can be repeated, bypassed, or modified as needed to meet the needs of the implementation.

Although discussed above in terms of treating an existing well having depleted regions 16 and under-developed regions 17, the processes in FIGS. 4A-4D can be used in a new well, a recently treated well, an infill well, or other type of well.

As shown in FIG. 5, an integrated fluid-geomechanics workflow 200 can be used to configure steps of the treatment operation (100), to operate the treatment system (10), and to control the surface equipment (30). The workflow 200 can be operated on processing equipment 250 to model, plan, and execute the steps of the operation and can use information in memory storage 252 obtained from a number of known sources, such as production data, initial well design, initial fracture treatment, logging information, core samples, etc.

In general, the workflow 200 can have a selection module 210 to select candidate wells, regions, zones, etc. This selection can then be processed with design modules 220, 230 for ultimate passage to an execution module 240 used to control the equipment (30) in the operation (100), such as the controls executed by the controller (90) of the system 10.

For example, the workflow 200 may start with the selection module 210 to select wells and/or stages for treatment. This module 210 may contain input data and may compare and contrast fracture potential between multiple well(s) or well stage(s). The input data may be collected from multiple sources, including core samples, log data, and field data. The collected data and/or attributes may include reservoir characteristics (e.g., depth, pore pressure gradient, porosity, permeability, total organic content (TOC), water saturation) and the geo-mechanical properties of the play (e.g., Young's modulus, Poisson's ratio, rock strength, cohesion and shmin gradient (minimum horizontal in-situ stress)), which may be ranked and integrated to predict the fracture potential.

Once the most viable candidate wells and/or stages are chosen, experimental data, field test results, and numerical analysis may be conducted to determine fluid/proppant/gas characteristics. The property design module 220 is then used to design/configure the characteristics of the fluid, proppant, and gas to be used in the operation (100), and the fracture and EOR design module 230 is used to design/configure the characteristics of the treatment, resultant production, etc.

These modules 220, 230 use computational models, such as geomechanical and reservoir models, and are used to provide operational parameters (e.g., flow rate, duration, proppant type, fluid type, gas type, gas pressure, etc.) to configure the operation 100 to meet goals, such as good lateral coverage, proppant deliverability, EOR efficiency, and maximized production. The computational models can include empirical information covering proppant movement under gas and liquid injection, determined liquid-gas or gas-liquid ratios, liquid-gas compatibility studies, rock characterizations, enhanced oil recovery character, etc.

Simulation results can also be generated using a 3-D reservoir scale fracturing simulator to model hydraulic fracture propagation, natural fracture reactivation, and proppant transport within both hydraulic fracture and reactivated fracture networks. The numerical simulations can be based on Fracture Mechanics (FM) and Fluid Dynamics (FD). FM uses numerical analysis to analyze (or solve) fracture propagation inquiries or problems by applying theories of elasticity and plasticity to predict the rock failure behavior with respect to intrinsic mechanical properties and applied boundary conditions. FD simulates interactions involving fracturing fluid flow, fracture surfaces, proppant transport, and boundary conditions. The coupled FM and FD may be used to determine the parameters affecting the proppant distribution within a developed fracture network such as, for example, injection rate, injection duration, fluid type, gas type, proppant type, and proppant concentration in the fluid, etc.

The modules 220, 230 can use computational models, such as Computational Fluid Dynamics (CFD), Discrete Element Methods (DEM), and geo-mechanical models. CFD is a computer-based mechanism for making calculations to simulate interactions involving the liquids, gases, surfaces, and boundary conditions for the disclosed operation. DEM is a computer-based mechanism for computing particle (including proppant and particulate diverting agents utilized in this operation) motion and interaction. Coupled CFD and DEM analysis may optimize the parameters affecting proppant transport properties such as, for example, fluid viscosity, fluid velocity, gas velocity, proppant size, proppant density, and proppant concentration (in the fluid).

The fracture design module 230 may first simulate proppant transport using the fluid and proppant properties exported from the previous analysis and may quantify proppant coverage and distribution using an advanced geo-mechanical model. The geo-mechanical analysis may model hydraulic fracture propagation, fracture height growth, natural fracture reactivation, and proppant transport within both new fractures and reactivated fracture networks. The geo-mechanical model may also simulate enhanced oil recovery, may simulate proppant mechanical deformation (both embedment and crush), and may simulate the resulting EOR and fracture closure behavior during production to quantify conductivity reservoir volume for production analysis. Once an acceptably optimized engineering design is obtained, the workflow 200 may output design parameters to the execution module 240 for use in controlling the treatment operation (100).

As noted previously, the disclosed operation can benefit from a synthetic fluid and techniques disclosed in U.S. application Ser. No. 15/666,327, filed 1 Aug. 2017, which has been incorporated herein by reference. In particular, a technique according to the present disclosure used for hydraulically fracturing and enhanced oil recovering a hydrocarbon-producing subterranean formation includes (a) ranking candidates (e.g., wells or well sections) of the subterranean formation for hydraulic fracturing; (b) performing numerical analysis to quantify a proppant-carrying capacity of selected fracturing fluid and enhanced oil recovery efficiency of injected gas on the ranked candidates; (c) selecting operational parameters of the selected fracturing fluid and the injected gas based on the numerical analysis; (d) delivering the fracturing fluid, the injected gas, and a proppant to the ranked candidates of the subterranean formation at the selected operational parameters; (e) temporarily sealing at least one energized fracture of the ranked candidates with diverter; and (f) interfacing the injected gas temporarily sealed in the at least one energized fracture with residual formation fluid therein.

To select the operational parameters, selection can be made to one or more of a fracturing fluid type, a gas type, a proppant type, a proppant concentration, a pumping rate, and an alternating frequency between fluid and gas. Ranking the candidates can be based on a consideration of one or more factors selected from the group consisting of reservoir depth, pore pressure gradient, porosity, permeability, total organic content (TOC), water saturation, Young's modulus, Poisson's ratio, rock strength, cohesion and shmin gradient.

Overall, selecting the operational parameters can be performed with respect to a defined geological condition using an integrated fluid-geomechanics workflow. Additionally, selecting the operational parameters can involve performing a number of simulations, including: performing a simulation to predict a hydraulic fracture propagation, a fracture height growth, and a natural fracture reactivation; performing a simulation to model proppant transport within both main hydraulic fractures and a reactivated natural fracture network; performing a simulation to model a fluid diversion process; performing a simulation to assess a proppant embedment and crush and fracture surface closure behavior during production; performing a simulation to simulate the enhanced oil recovery; and performing a simulation to forecast the enhanced oil recovery and production efficiency. A best stimulation design is chosen based on a comparison of the predicted result corresponding to a typical design plan. Fracturing parameters of the planned stimulation operations are optimized based upon an extent of conductive reservoir volume, the enhanced oil recovery efficiency, and the production efficiency.

To select the operational parameters, a modified pumping schedule can also be selected or configured. The modified pumping schedule can be selected/configured by changing an injection time, rate, proppant type, gas type, fluid properties, liquid-gas or gas-liquid ratios, and alternating frequency between liquid and gas. The fluid properties can include viscosity and density affecting fracture propagation and proppant transport process. In selecting the modified pumping schedule, a change of the fluid properties, the gas type, and impact on the proppant carrying capacity, enhanced oil recovery, and fracture extent can be quantified by performing numerical analysis.

Various numerical analyses can be performed to quantify the proppant-carrying capacity. For example, numerical analysis can be performed to quantify the proppant-carrying capacity under gas and liquid injection, liquid-gas compatibility, and enhanced oil recovery character. Numerical analysis can be performed to quantify the proppant-carrying capacity under gas and liquid injection, liquid-gas compatibility, and enhanced oil recovery character with respect to fluid density, fluid viscosity, gas density, gas velocity, and formation fluid composition. Numerical analysis can be performed to quantify the proppant-carrying capacity under gas and liquid injection with various proppant types and concentrations.

The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter. Although disclosed in terms of re-fracturing an existing well, the disclosed treatment can be used for initial fracturing operations of a new well, an infill well, or other well and can be used for treating a wellbore having natural fractures or a recently treated well.

In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof. 

1. A method of fracturing a well having at least one region including one or more existing fractures formed therein, the method comprising: stimulating the at least one region by alternating between pumping one or more first liquid intervals and injecting one or more first gas intervals to the at least one region; energizing at least one of the one or more existing fractures of the at least one region with the stimulation; carrying proppant into the at least one energized fracture with the stimulation fluid; temporarily sealing the at least one energized fracture with a diverter in the well; and interfacing the injected gas temporarily sealed in the at least one energized fracture with residual formation fluid therein.
 2. The method of claim 1, wherein liquid for the one or more first liquid intervals comprises at least one of a water-based fluid, an oil-based fluid, a polymer-based fluid, a foam, slick water, a synthetic fluid with low viscosity fluid and a high proppant carrying capacity, a linear gel, a cross-linked gel, and a liquefied gas; wherein gas for the one or more first gas intervals comprises at least one of produced gas, produced lean gas, carbon dioxide, ethane-dominated gas, and rich hydrocarbon gas; and wherein the diverter comprises at least one of a mechanical tool, a plug, a sliding sleeve, a particular diverter, a chemical diverter, a polyactic acid (PLA), and a ployglycolic acid (PGA).
 3. The method of claim 1, wherein pumping the one or more first liquid intervals to the at least one region comprises delivering the proppant with at least one of the one or more first liquid intervals.
 4. The method of claim 3, wherein pumping the at least one first liquid interval delivering the proppant comprise suspending the proppant in pumped liquid of the at least one first liquid interval; and delivering the pumped liquid comprising the suspended proppant into the existing fractures.
 5. The method of claim 1, wherein injecting the one or more first gas intervals in the well comprises injecting at least one of the one or more first gas intervals at a pressure at least at or above a fracture initiation pressure of the at least one region.
 6. The method of claim 1, wherein injecting the one or more first gas intervals in the well comprises injecting at least one of the one or more first gas intervals at a pressure at or above reservoir pressure of the at least one region.
 7. The method of claim 1, wherein stimulating the at least one region comprises configuring one or more characteristics of at least one of the proppant, the one or more first liquid intervals, and the one or more second gas intervals for the at least one region.
 8. The method of claim 1, wherein to energize the at least one existing fracture, the method comprises determining an amount of pressure in the one or more first liquid intervals sufficient to reopen the at least one existing fracture.
 9. The method of claim 1, wherein energizing the at least one existing fracture comprises: entering gas from the one or more first gas intervals into the at least one existing fracture in the at least one region; and interfacing the entered gas with the residual formation fluid in a vicinity of the at least one existing fracture.
 10. The method of claim 1, wherein energizing at least one of the one or more existing fractures of the at least one region with the stimulation further comprises extending at least one of the one or more existing fractures of the at least one region with the stimulation and carrying the proppant into the extension of the at least one extended fracture of the at least one region with the stimulation.
 11. The method of claim 10, wherein to extend the at least one existing fracture, the method comprises determining an amount of pressure and fluid volume sufficient to induce additional fracture length of the at least one existing fracture.
 12. The method of claim 1, wherein carrying the proppant into the at least one energized fracture with the stimulation comprises: carrying the proppant into the at least one energized fracture with at least one of the one or more liquid intervals; and moving the proppant further with turbulence created by interaction of at least one of the one or more gas intervals with the one or more liquid intervals.
 13. The method of claim 1, wherein temporarily sealing the at least one energized fracture with the diverter in the well comprises at least one of: operating a mechanical tool as the diverter, installing a plug as the diverter, closing a sliding sleeve as the diverter, pumping a particular diverter as the diverter, and pumping a chemical diverter as the diverter adjacent the at least one energized fracture.
 14. The method of claim 1, wherein interfacing the injected gas temporarily sealed in the at least one energized fracture with the residual formation fluid therein comprises using at least one of a vaporization, swelling, and miscibility mechanism.
 15. The method of claim 1, further comprising producing fluid from the at least one region upon completion of the re-fracturing.
 16. The method of claim 1, further comprising: stimulating the at least one region by alternating between pumping one or more second liquid intervals and injecting one or more second gas intervals in the well to the at least one region; energizing at least one other of the one or more existing fractures of the at least one region with the stimulation; and carrying the proppant into the at least one other energized fracture with the stimulation.
 17. The method of claim 1, further comprising: stimulating the at least one region by alternating between pumping one or more second liquid intervals and injecting one or more second gas intervals to the at least one region; and creating at least one new fracture in the at least one region with the stimulation; and carrying proppant into the at least one new fracture with the stimulation.
 18. The method of claim 17, wherein alternating between pumping the one or more second liquid intervals and injecting the one or more second gas intervals in the well to the at least one region comprises: pumping a first of the one or more second liquid intervals to create the at least one new fracture; pumping, thereafter, a second of the one or more second liquid intervals with the proppant to carry the proppant into the at least one new fracture; and injecting, thereafter, a first of the one or more second gas intervals to the at least one new fracture to further carry the pumped proppant into the at least one new fracture and to interface the injected gas with the residual formation fluid in a vicinity of the at least one new fracture.
 19. The method of claim 17, wherein alternating between pumping the liquid and injecting the gas in the well to the at least one region comprises: pumping a first of the one or more second liquid intervals to create the at least one new fracture; pumping, thereafter, a second of the one or more second liquid intervals with the proppant to carry the proppant into the at least one new fracture; injecting, thereafter, a first of the one or more second gas intervals to the at least one new fracture; and pumping, thereafter, a third of the one or more second liquid intervals to compress the injected gas in the at least one fracture.
 20. A method of fracturing a well, the method comprising: stimulating at least one region of the well by alternating between pumping one or more first liquid intervals and injecting one or more first gas intervals to the at least one region of the well; creating at least one fracture in the at least one region with the stimulation; carrying proppant into the at least one fracture with the stimulation; temporarily sealing the at least one fracture with a diverter in the well; and interfacing the injected gas temporarily sealed in the at least one fracture with formation fluid therein.
 21. The method of claim 20, wherein alternating between pumping the one or more first liquid intervals and injecting the one or more first gas intervals in the well to the at least one region comprises: injecting a first of the one or more first gas intervals at least above a fracture initiation pressure to create the at least one fracture; pumping, thereafter, a first of the one or more first liquid intervals with the proppant to carry the proppant into the at least one fracture; and injecting, thereafter, a second of the one or more first gas intervals to the at least one fracture to further carry the pumped proppant into the at least one fracture and to interface the injected gas with the residual formation fluid in a vicinity of the at least one fracture.
 22. The method of claim 20, wherein injecting the first of the one or more first gas intervals at least above the fracture initiation pressure to create the at least one fracture further comprises filling the at least one fracture with the injected gas.
 23. The method of claim 20, wherein pumping the first of the one or more first liquid intervals further comprises extending the at least one fracture.
 24. The method of claim 20, wherein alternating between pumping the one or more first liquid intervals and injecting the one or more first gas intervals in the well to the at least one region and creating the at least one fracture comprises: pumping a first of the one or more first liquid intervals to create the at least one new fracture; pumping, thereafter, a second of the one or more first liquid intervals with the proppant to carry the proppant into the at least one new fracture; and injecting, thereafter, a first of the one or more first gas intervals to the at least one fracture to further carry the pumped proppant into the at least one fracture and to interface the injected gas with the residual formation fluid in a vicinity of the at least one fracture.
 25. The method of claim 24, further comprising pumping, thereafter, a third of the one or more first liquid intervals to compress the injected gas in the at least one fracture.
 26. The method of claim 24, wherein alternating between pumping the one or more first liquid intervals and injecting the one or more first gas intervals in the well to the at least one region comprises pumping an initial one of the one or more first gas intervals in the well before first pumping the first liquid interval.
 27. A system for fracturing a well, the system comprising: pumping equipment in fluid communication with the well and configured to pump one or more of liquid intervals into the well at pressure; delivery equipment in fluid communication with the pumping equipment and configured to deliver one or more of proppant and diverter to at least one of the one or more of the pumped liquid intervals; and gas injection equipment in fluid communication with the well and configured to inject one or more gas intervals into the well; the system using the pumping, delivery, and gas injection equipment and being configured to: alternate between pumping the one or more liquid intervals and injecting the one or more gas intervals to the region to stimulate at least one region of the well; energize at least one fracture of the at least one region with the stimulation; carry the proppant into the at least one energized fracture with the stimulation; temporarily seal the at least one energized fracture with the diverter; and interface the injected gas temporarily sealed in the at least one energized fracture with residual formation fluid therein.
 28. The system of claim 27, wherein to energize the at least one fracture of the at least one region with the stimulation, the system is configured to at least one of: energize the at least one fracture from one or more existing fractures of the region with the stimulation; and create the at least one fracture in the at least one region with the stimulation.
 29. The system of claim 27, wherein the gas injection equipment comprises one or more compressors compressing gas for the one or more gas intervals.
 30. A method of hydraulically fracturing and enhanced oil recovering a hydrocarbon-producing subterranean formation, the method comprising: ranking candidates of the subterranean formation; performing numerical analysis to quantify a proppant-carrying capacity of selected fracturing fluid and enhanced oil recovery efficiency of injected gas on the ranked candidates; selecting operational parameters of the selected fracturing fluid and the injected gas based on the numerical analysis; delivering the fracturing fluid, the injected gas, and a proppant to the ranked candidates of the subterranean formation at the selected operational parameters; temporarily sealing at least one energized fracture of the ranked candidates with diverter; and interfacing the injected gas temporarily sealed in the at least one energized fracture with residual formation fluid therein. 31-41. (canceled) 